When a fluid, such as oil and natural gas, is being produced from a subterranean reservoir through a wellbore, the ability of the reservoir to produce hydrocarbons and other fluids is often enhanced by processes that inject fluids and solids from surface into the well reservoir. These fluids are known to those of skill in the art of oil and gas production as stimulation fluids or hydraulic fracturing fluids and the injection process at a well site in which they are used is often referred to as a stimulation or fracture treatment. The fluids to be injected are often mixed at surface with a variety of chemicals and solids prior to injection. A wide variety of fluid types may be used including freshwater, saltwater, nitrogen, carbon dioxide, hydrogen peroxide, acids, bases, surfactants, alcohols, diesel, propane, liquid natural gas, and many more fluids which are well known to those of skill the upstream oil and gas industry. Oftentimes, there are additional chemicals and fluids mixed at surface and injected in such a stimulation processes in order to improve the ability of the reservoir to produce the injected stimulation fluids back to surface. This is because the stimulation fluids remaining in the reservoir or the chemicals transported by said fluids can often times reduce the ability of the reservoir to produce desired fluids into the well. Additionally, typical stimulation practice involves combining, at the surface, viscosity agents, cross-linkers, and possibly other components, to the stimulation fluid, enhancing the ability of the fluids to transport solids into the reservoirs, create hydraulic fracture growth or both. A still further reason to add chemicals (including but not limited to guars such as such as hydroxypropyl guars, polyacrylamides, cellulose gelling agents, miscellars, surfactants, and others) to stimulation fluids is to reduce the hydraulic friction between the fluids being pumped and the well conduits that transport the fluids from surface to the subterranean reservoir. These are often referred to as friction reduction chemicals. Without the friction reduction chemicals, the amount of hydraulic horsepower required to inject fluids into the well becomes higher requiring more surface pumping power and equipment thereby, drastically increasing the cost of a stimulation treatment. Hence, one often faces the dilemma whereby if one performs a stimulation or hydraulic fracture treatment without friction reducer chemicals in the fluid, the cost of injection is much higher due to energy costs, but if one opts to mix at surface friction reduction chemicals in the stimulation or hydraulic fracture fluid to reduce horsepower requirements, damage to the subterranean reservoir from said friction reducers occurs.
Furthermore, as fluids are flowed back to the surface after the injection process these flowed-back fluids containing chemicals used during the injection cause environmental damage to the surface environment and to well tubular that transduce them to surface. This damage can be scale deposits in the well casing, corrosion in the well casing, and detrimental effects on surface flow back equipment. Often to reduce the surface damage to the environment, the fluids must be treated with additional chemicals at the surface or specially disposed of at surface, further increasing the cost to using fluids and chemicals on injection jobs like said stimulation and fracture treatments.
Moreover, there are other problems with these injected fluids when they are produced back from the wells. Typically, they must be treated in order to be reused on a subsequent stimulation or hydraulic fracture treatment or disposed of in a safe and environmentally proper manner. There are many detrimental issues with this produced-back stimulation fluid, mostly owing to the fact that the produced-back fluids are complex mixtures of a number of chemical materials and are further contaminated from the subterranean environment after the injection process and often contain bacteria, salts, scales, gases, enzymes, viruses, and other materials that are not suitable for surface handling, disposal or re-injection into wells during a subsequent stimulation or hydraulic fracture process.
The current method used by those familiar with the art of treating stimulation fluids is to mix chemical compositions, including but not limited to, friction reducers, gelling agents, crosslinkers, surfactants, into fluids at surface prior to injecting them down a well casing or tubing. These compositions are typically batch-mixed into the stimulation fluids to be injected at surface into large holding tanks, known as “frac tanks”, surface pits, and ponds, or the chemicals are added on the fly at surface by injecting them into the discharge of a large centrifugal pump at surface, allowing for a large amount of shear to be introduced to the mixing of the chemicals with the stimulation injection fluid. The fluid mixture, after mixing at the centrifugal pump is then often pumped through high pressure pumps to allow the fluids to be injected into the well and subsequently the reservoir at very high pressures and normally high injection rates, thereby exceeding the fracture pressure of the reservoir rock. This process is often referred to as “hydraulic fracturing”. These compositions injected at surface often reduce the hydraulic friction pressure developed between the well tubular and the fluids being pumped down the well hence the required hydraulic horsepower for the injection, but the result is that the chemicals mixed at surface often cause residual damage to the reservoir. The damage often diminishes subsequent production of hydrocarbons from the reservoir. This damage results in part, because these chemicals, usually large polymer chains, have long molecular structures and significant surface tension, making their recovery from the reservoir rock during stimulation flow back difficult. Furthermore, the stimulation fluids having the chemicals mixed into them at surface, and having a certain amount of oxygen entrained from the surface mixing process, react in-situ in the reservoir enhancing bacterial growth and resulting in unwanted gas, bacterial growth, fluid pH modifications and scale. These surface-mixed chemicals and fluids combine in the reservoir with heat and oxygen from the surface to accelerate bacteria growth in the stimulation fluid leading to the detrimental generation of in-situ gases, bacteria, fluid pH modifications, and scale, that combine with these reservoir fluids and polymers to cause corrosion and scale precipitation to occur in the reservoir and well. Furthermore, these chemicals and fluids, when flowed back to the well surface, result in toxic surface fluids that are note easily and inexpensively disposed. Finally, the flowed back stimulation fluids with the injected chemicals and fluids now representing bacterial loaded fluids are unsatisfactory to re-inject during subsequent well stimulation treatments.
Another method used by those familiar with the art of treating stimulation fluids is to add a cross-linker chemical to a gelled fluid at surface. The gel is often batch mixed into surface frac tanks, and then the cross-linker is added in a centrifugal pump thereby mixing the batch mixed geld fluids from the frac tank with the fluid containing the cross-linker at the surface in the centrifugal pump. The viscosity of the cross-linked fluid composition increases as combined fluids go through high pressure positive displacement pumps and proceed down the well, thereby allowing the cross-linked fluid to transport a slurry of particles, known as “proppants” to those of skill in the art, into the reservoir rock. In this technique of adding crosslinker fluids at surface, it is desirable that the combination of cross-linker and gelled fluid be designed to achieve maximum viscosity to transport proppants into the reservoir, that is maximum crosslinking, approximately when the mixed fluids are near the depth of the perforations. If crosslinking occurs in the fluid too quickly, then there will be excessive viscosity developed in the fluid being transported through the well tubulars causing increased fluid hydraulic friction between the fluid and the well conduit too early in the transport time of the fluid in the well conduit, thereby causing the surface injection pressure to become excessively high and resulting in the need for more surface hydraulic horsepower to inject the fluids. This timing of cross linking is difficult to achieve in practice as it is a function of the well depth, well temperature, fluid pH, fluid temperature, gel and crosslinker mixing proportions achieved on surface in a dynamic “on the fly” mixing process, and the injection rate of the fluids. Currently, the crosslinking effect cannot be quickly controlled and changed from surface as the fluids in the well have already been mixed at surface and because the reservoir being injected to can be miles away in depth from the surface, hence the transient time between the time at which the crosslinked fluid is injected at surface and the time at which it arrives at the perforations in the reservoir is typically longer than is desirable. In a stimulation treatment, it is often useful to control and change rapidly the crosslinking effect and the resulting viscosity of the injected fluids. For example, one may desire to keep the viscosity low while the fluid is in the pipe to reduce the hydraulic horsepower required to inject the stimulation fluids but just as the injected fluid begins to enter the perforations one might want the viscosity to increase rapidly. However, when surface mixing crosslinkers or other fluid viscosity modifiers, it very difficult to rapidly change the friction pressure of the fluids by the effect of crosslinking of the gelled fluid. This is due to a number of reasons, including the significant distances that the fluid being injected must travel from the surface to the reservoir and resulting long transit time. A still further problem presented by current oil and gas industry methods of crosslinking and viscosity-modifying fluids is that is in many wells, fluids are injected in large zones separated by many thousands of feet. It often occurs during the course of a stimulation treatment that a particular portion of the injection zone takes a disproportionate amount of the stimulation treatment and a method to change the injection profile during the job is needed. This is often referred to in the art as diverting the fluids or conformance control of the injection profile.
What is needed is a method to reduce the damage done in-situ to hydrocarbon reservoirs and subsequently the environmental damage done on the surface of the earth and sea by the flow back to surface of these fluids and chemicals injected to wells. A further need is to more accurately and quickly control injection fluid viscosity from surface with a down-hole mixing method. A still further need is to change the injection profile of injection fluids using a down hole injection and mixing method for chemicals and insitu methods to monitor the same. Another need is to actively treat the injection fluids during their flow back to surface after a stimulation job.